Net oil and gas well test system

ABSTRACT

A method of assessing flow from an individual well in a set of oil and gas wells includes flowing output from a first subset of the wells collectively to a first flow measurement system through a first conduit while flowing output from a second subset of the wells collectively to a second flow measurement system through a second conduit different from the first conduit. Total flow through the first flow measurement system and total flow through the second measurement system are measured. Output from said individual well is rerouted from one of said first and second measurement systems to the other of said first and second measurement systems. Total flow through at least one of the first and second measurement systems is measured after the re-routing. A difference between the total flow rate before the re-routing and after the re-routing is used to assess flow rate from said individual well.

CROSS REFERENCE

This application is a division of U.S. patent application Ser. No.14/084,245, filed Nov. 19, 2013, now U.S. Pat. No. 9,562,427, whichclaims priority to U.S. provisional application No. 61/825,872, filedMay 21, 2013 and to U.S. provisional application No. 61/728,224, filedNov. 19, 2012, the contents of which are all hereby incorporated byreference.

FIELD OF THE INVENTION

The present invention generally relates to systems and methods formeasuring fluids produced from oil and gas wells and more particularlyto such systems and methods that use multiphase flow meters, such asmultiphase Coriolis meters, to measure flow of oil, gas, and water fromoil and gas wells. Some aspects of the invention relate more generallyto measurement of multiphase fluid flow and also have applicationsoutside the oil and gas industry.

BACKGROUND

Various different flowmeters are used in the oil and gas industry toprovide information about the fluids produced by oil and gas wells. Onesuch flowmeter is a Coriolis flowmeter. As is known to those skilled inthe art, a Coriolis flowmeter includes a vibrating flowtube throughwhich the process fluid passes and an electronic transmitter. Thetransmitter maintains flowtube vibration by sending a drive signal toone or more drivers and performs measurement calculations based onsignals from two sensors. The physics of the device dictates thatCoriolis forces act along the measurement section between sensors,resulting in a phase difference between the sinusoidal sensor signals.This phase difference is essentially proportional to the mass flow rateof the fluid passing through the measurement section. Thus, the phasedifference provides a basis for a mass flow measurement of fluid flowingthrough the flowtube. The frequency of oscillation of the flowtube of aCoriolis meter varies with the density of the process fluid in theflowtube. The frequency value can be extracted from the sensor signals(for example by calculating the time delay between consecutive zerocrossings) so that the density of the fluid can be obtained. Theflowtube temperature is also monitored to enable compensation forvariations in flowtube stiffness that may affect the oscillationfrequency.

Coriolis meters are widely used throughout various different industries.The direct measurement of mass flow is frequently preferred overvolumetric-based metering, for whereas the density and/or volume of amaterial may vary with temperature and/or pressure, mass remainsunaffected. This is particularly important in the oil and gas industry,where energy content and hence product value is a function of mass.

A Coriolis meter measuring two parameters—mass flow and density—istheoretically able to resolve a two-phase (liquid/gas) mixture. However,unless simplifying assumptions are made, a Coriolis meter cannot on itsown resolve the general three-phase oil/water/gas mixture thatcharacterizes most oil well production. Including a third measurement ofthe fluid flow, such as water cut, (the proportion of water in theliquid mixture, typically scaled between 0% and 100%), enables truethree-phase metering to be achieved. The term ‘Net Oil’ is used in theupstream oil and gas industry to describe the oil flow rate within athree-phase or a liquid (oil/water) stream. A common objective in theoil and gas industry is to determine the net oil produced by each wellin a plurality of wells because this information can be important whenmaking decisions affecting production from an oil and gas field and/orfor optimizing production from an oil and gas field.

A conventional oil and gas well test system is shown in FIG. 1. In thiswell test system, one well from a plurality of wells (i.e., a cluster ofN wells) is introduced into a test separator at any one time, while theremaining wells (i.e., N−1) are combined for transport to the productionfacility. The output of the selected well is separated in order toderive volumetric flow rates of the oil and gas being outputted from theselected well. The gas-liquid test separator flow path may besubstantially different from that of the same well using the “bypass”route. Therefore, the well production in the test separator flow pathmay not be truly representative of its production the majority of thetime when it is following the bypass route.

The present inventors have made various improvements, which will bedescribed in detail below, applicable to the field of Coriolisflowmeters and applicable to the field of net oil and gas testing.

SUMMARY

An oil and gas well test system includes first and second measurementsystems (e.g., a Coriolis-based measurement system) and a plurality ofvalves for connecting each of a plurality of wells of a cluster to oneof the first and second measurement systems. The state of the valves canbe switched to selectively change which of the measurement systems is influid communication with a selected well. A controller of the system isconfigured to calculate a parameter (e.g., volume or mass flow) of anoutput of the well that is associated with a valve that has beenswitched, based on the received default and switched data from the firstand second measurement systems. A method of calculating the parameter isalso disclosed.

Another aspect of the invention is a measurement controller fordetermining a parameter of an output from each individual well in a setof wells. The measurement controller includes a measurement controllerincluding a processor and a memory. The measurement controller isadapted for communication with a plurality of valves, each of which isconfigured for fluid communication with one of the individual wells, andfirst and second net oil and gas measurement systems. The measurementcontroller is configured to: (i) receive default data from the first andsecond net oil gas measurement systems when a first valve of theplurality of valves is in a first state and fluidly connects thecorresponding well to the first net oil and gas measurement system, anda second valve of the plurality of valves is in a second state andfluidly connects the corresponding well to the second net oil and gasmeasurement system; (ii) switch the first valve from the first state tothe second state so that the first valve fluidly connects thecorresponding well to the second net oil and gas measurement system;(iii) receive switched data from the first and second net oil gasmeasurement systems after switching the first valve from the first stateto the second state; and (iv) calculate a parameter of an output of thewell that is associated with the first valve based on the receiveddefault and switched data.

Another aspect of the invention is a method of assessing flow from a setof oil and gas wells. The method includes flowing output from a firstsubset of the wells collectively to a first flow measurement systemthrough a first conduit while flowing output from a second subset of thewells collectively to a second flow measurement system through a secondconduit different from the first conduit. Total flow through the firstflow measurement system and total flow through the second measurementsystem are measured. Output from said individual well is re-routed fromone of said first and second measurement systems to the other of saidfirst and second measurement systems. Total flow through at least one ofthe first and second measurement systems is measured after there-routing. A difference between the total flow rate before there-routing and after the re-routing is used to assess flow rate fromsaid individual well.

Still another aspect of the invention is a multi-phase flow meteringsystem for measuring a multi-phase fluid including oil, water, and gas.The system includes a Coriolis mass flow meter adapted to measure massflow rate and density of the multi-phase fluid. The system has a watercut meter adapted to measure the water cut of the multi-phase fluid. Aprocessor is configured to determine the oil mass flow rate of the oil,water mass flow rate of the water, and gas mass flow rate of the gasusing the mass flow rate and density from the Coriolis meter and thewater cut from the water cut meter. The processor is further configuredto determine dynamic estimates of the uncertainty of each of the oilmass flow rate, water mass flow rate, and gas mass flow rate.

Other objects and features will be in part apparent and in part pointedout hereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is schematic diagram illustrating a conventional oil and gas welltest system;

FIG. 2 is a schematic diagram of one embodiment of an oil and gas welltest system;

FIG. 3 is a side elevation of one embodiment of a net oil skid suitablefor use in the oil and gas well test system of FIG. 2;

FIG. 4 is a perspective of one embodiment of a Coriolis meter suitablefor use in the net oil skid of FIG. 3 and for use in the oil and gastest system illustrated in FIG. 2;

FIG. 5 is a side elevation of the Coriolis meter shown in FIG. 4;

FIG. 6 is a schematic diagram illustrating some of the electronicarchitecture of the net oil skid of FIG. 3;

FIG. 7 is a graph illustrating one example of a relationship betweenobserved mass flow rate, observed density drop, and a density drop errorthat can be used to provide improved measurements using the Coriolismeter of FIGS. 4 and 5;

FIG. 8 is a graph illustrating low liquid mass flow error as the watercut of a multiphase flow is varied across a wide range of values between0 and 100 percent;

FIG. 9 is a display showing a time-varying void fraction for each of theconstituents of a multiphase flow in the upper portion of the displayand a corresponding time varying flow rate of gas, oil, and watermeasured from the multiphase flow;

FIG. 10 is a schematic diagram illustrating one embodiment of aself-validating sensor; and

FIG. 11 is a schematic flow diagram of a system for providinguncertainty estimates for the constituents of a multiphase flow.

Corresponding reference characters indicate corresponding partsthroughout the drawings.

DETAILED DESCRIPTION

Referring to FIG. 2, one embodiment of an oil and gas well test systemis generally indicated at 100. The oil and gas well test system 100includes a plurality of well-output conduits 102 (e.g., pipes) fluidlyconnected to a set of N wells 101. Although there are 4 wells 101illustrated in FIG. 2, the number of wells N in a set can vary. Thewells 101 are typically a cluster of wells producing from the same oiland gas reservoir and/or sharing a common production facility 120. Eachwell output conduit 102 is suitably connected to a single well 101 sothe fluids produced by each individual well are isolated in thecorresponding conduit 102. Each well-output conduit 102 is in fluidcommunication with one of a plurality of valves 104 (e.g., a pluralityof 3-way valves). For reasons explained below, each valve 104 isindependently configurable between a first state, in which the valvefluidly connects the corresponding well-output conduit 102 to a firstinlet conduit 108 to direct fluid flow to a first net oil and gasmeasurement system 110, and a second state, in which the valve fluidlyconnects the corresponding well-output conduit to a second inlet conduit111 to direct well flow to a second net oil and gas measurement system112. The output from each well 101 in the set can be selectively routedto either of the oil and gas measurement systems 110, 112, independentlyof the output from the other wells. After flowing through the first andsecond net oil and gas measurement systems 110, 112, the well flow maybe delivered to the production facility 120. The sum of the flow throughthe first and second net oil and gas measurement systems 110, 112 isessentially the combined flow of fluids produced from all N wells. Theoil and gas well test system 100 may also include a first pressureregulation valve 116 fluidly connecting the first inlet conduit 108 tothe first net oil and gas measurement system 110, and a second pressureregulation valve 118 fluidly connecting the second inlet conduit 112 tothe second net oil and gas measurement system 114.

Each of the first and second net oil and gas measurement systems 110,112, respectively, may include a Coriolis flowmeter system (alsoreferred to as a “Coriolis-based net oil metering skid”) that allows themeasurement of gas, oil and water directly from the wellhead withoutfirst separating the components using the conventional gas-liquidseparator. This Coriolis-based metering skid can provide severaladvantages over the separator-based oil and gas well test system,including, but not limited to 1) not requiring separation of the output,so that natural flow pattern of the well is more readily captured, 2)accurate flow rates can be captured in minutes, rather than hours, and3) it facilitates a smaller footprint and reduced maintenance comparedto conventional well test systems. It is understood that each of thefirst and second net oil and gas measurement systems 110, 112 mayinclude a different type of flowmeter system, including a flowmetersystem having a gas-liquid separator within the scope of the invention.The first and second net oil and gas measurement systems can beidentical, as is the case in the illustrated embodiment, but it is alsorecognized that this is not required within the broad scope of theinvention.

An example of one embodiment of a Coriolis-based metering skid for usein the well test systems 110, 112 is the Foxboro® multiphase measurementnet oil and gas solution available from Invensys Systems, Inc. Adetailed description of a Coriolis net oil skid is also provided in U.S.Pre-grant Patent Application Publication No. 20120118077, the contentsof which are hereby incorporated by reference. In general, the net oilskid includes a conduit through which the fluid from the well flows; aCoriolis flowmeter for measuring mixture density and mass flow rate ofliquid and gas; a water cut meter for measuring the percentage of waterin the liquid; and a multi-variable pressure and temperature sensor formeasuring pressure and temperature for gas density reference are influid communication with the conduit.

One embodiment of a suitable net oil skid that can be used as ameasurement system is illustrated in FIG. 3. The skid 600 ismechanically designed to condition the process fluid flow to minimizeslip between gas and liquid via the rise and fall of the pipework, andby an integrated flow straightener in the horizontal top section. Inthis embodiment, a liquid fraction probe 230 is plumbed in series with amultiphase Coriolis flowmeter 215 between the system inlet 602 andoutlet 608. The liquid fraction probe 230 is suitably a watercut meter(or watercut probe) that measures and provides an estimate of thefraction of water in the fluid that flows through it. The fraction ofwater may be referred to as the water cut. The system 600 also includesan interface module 609, which may include an electronic processor, anelectronic storage (such as a memory), and one or more input/outputmodules (such as a display, a communications interface for connection toa transmitter in communication with the Coriolis flowmeter 215 and/orconnection with the liquid fraction probe 230, and/or for connection toa remote terminal (not shown), and a tactile manual input, such as akeyboard and a mouse). Together, the multiphase Coriolis meter 215 andliquid fraction probe 230 are able to measure flow rate of water, oil,and gas in a mixture containing all three of these constituents as theyare received in a multiphase flow from one or more of the wells 101.

In the system 600, the Coriolis flowmeter 215 is positioned and arrangedsuch that the fluid flows through the Coriolis flowmeter in a downwarddirection that corresponds to the direction of gravity. In the exampleshown in FIG. 3, the liquid fraction probe 230 and the Coriolisflowmeter 215 are in a downward orientation on a downward leg of theskid 600. Placement of the liquid fraction probe 230 and the Coriolisflowmeter 215 in a downward orientation on the downward leg of the skid600 may be beneficial in low pressure, high GVF applications, such asmay be encountered in some oil and gas wells, especially mature wellsproducing from depleted reservoirs. For example, as compared to a systemin which the Coriolis flowmeter is oriented such that fluid flows in theupward direction, arranging the system so fluid flows downward throughthe Coriolis flowmeter 215 may result in the Coriolis flowmeter drainingmore effectively. Additionally, separation of gas and liquid phases ofthe multi-phase fluid may occur naturally on the upward leg 610 of theskid 600 because gas passes through the flowtube 215 at any time,whereas liquid tends to collect in the upward leg 610 until asufficiently large slug of liquid is capable of passing through a topsection 611 of the skid 600 to the downward leg 608. Once the liquid haspassed through the Coriolis flowmeter 215, gravity acts to minimize, oreliminate, liquid flow back into the flowtube 215. In someimplementations, a device to further minimize backwash into the flowtube215, such as a non-return valve (not shown), may be included in the skid600.

Additionally, an arrangement such as shown in FIG. 3 may reduce thepossibility of the Coriolis flowmeter 215 being in a partially filledstate (or partially filled condition). For example, when liquid flowcompletely or nearly stops, as may occur for extended periods of timefor a low-producing oil and gas well, unless the Coriolis flowmeter 215drains completely, the flowtube 215 may enter a partially filled state.While in a partially filled state, the flowtube 215 may produce aspurious (inaccurate), non-zero mass flow reading, which in turn maylead to false readings of oil and water flows through the system 600.However, the arrangement shown in FIG. 3 reduces or eliminates thepossibility of liquid being trapped within the flowtube of the Coriolismeter 215, thus reducing or eliminating the occurrence of a partiallyfilled state and the effects of a partially filled state.

One embodiment of a Coriolis flowmeter, generally designated 215 isillustrated in FIGS. 4 and 5. The flowmeter 215 includes one or moreconduits 18, 20 (also referred to as a flowtube), one or more drivers 46a, 46 b for driving oscillation of the conduit(s),and a pair of motionsensors 48 a, 48 b that generate signals indicative of the oscillationof the conduit(s). In the illustrated embodiment, there are two conduits18, 20 two drivers 46 a, 46 band two motion sensors 48 a, 48 b and thedrivers and motions sensors are positioned between the conduits so eachdriver and motion sensor is operable for both of the conduits. It isunderstood by those skilled in the art that a Coriolis flowmeter mayhave only a single conduit and/or may have a single driver. It is alsounderstood the conduit(s) may have different configurations than theconduits 18, 20 in the illustrated embodiment.

As illustrated in FIGS. 4 and 5, the flowmeter 215 is designed to beinserted in a pipeline (not shown) having a small section removed orreserved to make room for the flowmeter. The flowmeter 215 includesmounting flanges 12 for connection to the pipeline, and a centralmanifold block 16 supporting the two parallel planar loops 18 and 20which are oriented perpendicularly to the pipeline. The drivers 46 a, 46b and sensors 48 a, 48 b are attached between each end of loops 18 and20. The drivers 46 a, 46 b on opposite ends of the loops 18, 20 areenergized by a digital controller (not shown) with current of equalmagnitude but opposite sign (i.e., currents that are 180° out-of-phase)to cause straight sections 26 of the loops 18, 20 to rotate about theirco-planar perpendicular bisector 56 (FIG. 5). Repeatedly reversing(e.g., controlling sinusoidally) the energizing current supplied to thedrivers 46 a, 46 b causes each straight section 26 to undergooscillatory motion that sweeps out a bow tie shape in the horizontalplane about the axis 56 of symmetry of the loops. The entire lateralexcursion of the loops at the lower rounded turns 38 and 40 is small, onthe order of 1/16 of an inch for a two foot long straight section 26 ofa pipe having a one inch diameter. The frequency of oscillation istypically about 80 to 90 Hertz, although this can vary depending on thesize and configuration of the flowtube(s).

As will be understood by those skilled in the art, the Coriolis effectinduces a phase difference between the two sensors 48 a, 48 b that isgenerally proportional to mass flow rate. Also, the resonant frequencyof the loops 18, 20 will vary as a function of density of the fluidflowing therethrough. Thus, the mass flow rate and density can bemeasured. The exploitation of new technology, such as audio qualityanalog-to-digital convertors and digital-to-analog convertors (ADCs andDACs) and Field Programmable Gate Arrays (FPGAs), has facilitated thedevelopment of new capabilities for Coriolis meters, such as the abilityto deal with multiphase flows. Various corrections can be applied to thebasic measurement resulting from the phase difference between thesensors. For example, multiphase flow introduces highly variable dampingon the flowtube, up to three orders of magnitude higher than in singlephase conditions, requiring agile and precise drive control. Inaddition, the mass flow and density measurements generated undermultiphase flow conditions are subject to large systematic and randomerrors, for which correction algorithms can be defined and implemented.Further details concerning operation of Coriolis flowmeters is providedin U.S. Pat. Nos. 6,311,136; 6,505,519; 6,950,760; 7,059,199; 7,188,534;7,614,312; 7,660,681; and 7,617,055, the contents of which are herebyincorporated by reference.

The Coriolis meter 215 and liquid faction probe 230 communicate with anet oil computer, such as the interface module 609 of the skid 600, thatcalculates a totalized net oil flow rate, water flow rate, and gas flowrate in mixed liquid/gas calculated in standard volume. The metrology ofthree-phase flow is complex, and in reality the uncertainty of eachmeasurement varies dynamically with the operating point, as well as themetering technology, and other aspects. A dynamic uncertainty analysisof the three-phase measurements would facilitate extending the range ofoperating conditions under which guaranteed measurement performancecould be provided. One way to achieve a three-phase flow uncertaintyanalysis is through the use of Monte-Carlo Modeling. The following willexplain how to provide an on-line assessment of the uncertainty of thethree-phase measurements, conforming to the SEVA concept, as specifiedin the British Standard BS-7986, as well as the international standardknown as the GUM—the Guide to the Expression of Uncertainty inMeasurement.

Multiphase flow regimes of oil, water and gas can present challenges foraccurately measuring the flow rates of the liquid and gas componentswith a Coriolis mass flow meter 215 and Water-Cut meter 230 basedmultiphase metering system. Specifically, variations in the flow regimecan create a slip condition where the flowing velocity of the compressedgas phase can vary significantly from that of the oil and water liquidphase, rendering accurate metering more difficult. As noted above, theskid 600 is designed to minimize this slip condition but there can stillbe slip between the gas and liquid phases.

Further challenges are presented as the Water-Cut meter 230 necessitatesa well-mixed oil and water flow stream to achieve desired measurementaccuracy of the water cut or percent of water in the oil and water flowstream. Where the flow regime result in significant slugging, it isimportant to preventing the meter from being subject to positive andthen negative flow conditions, as would occur if the meter 230 werepositioned on the inlet side of the skid 600. It is further important toensure that the meter 230 is properly drained, as it can be difficult todistinguish between true multi-phase flow and the potentially large flowand density errors induced by the partially filled conditions when thereis no genuine flow passing through the meter. This can be alleviated byusing a multiphase metering system design and implementation in whichthe potential slip condition between gas and liquid phases is minimizedto maintain a conditioned flow profile, where the Coriolis mass flowmeter 215 measures liquid and gas phases at normalized flow velocities.It is also helpful to facilitate good mixing of oil and water liquidphases to maintain a homogeneous flow regime at the point of Water-Cutmeter measurement.

Other instrumentation on the skid 600 consists of the water cut meterand a pressure and temperature transmitter (not shown). The latter readsthe pressure at the inlet to the Coriolis meter 215 and the temperatureof an RTD (resistance temperature detector) sensor in a thermal well,positioned at the top of the skid 600. The Hardware/Softwarearchitecture of the skid 600 is shown in FIG. 6. As illustrated theCommunications/Compute Unit (e.g., unit 609 on FIG. 3) acts as acommunication master for all the devices, using the Modbus RTUindustrial communications protocol, commonly used in the oil and gasindustry. The compute unit 609 performs three-phase flow measurementcalculations based on the data received, provides a user interface (forproviding, for example, gas and fluids density information) and alsocarries out data archiving. Real-time data is provided to the user'sdata acquisition system via a Modbus interface, with an update rate of 1second.

As illustrated there are three communication interfaces: an internalModbus for the skid 600 instrumentation, an external Modbus interface toprovide measurement values to the user, and an Ethernet interface toenable remote configuration, monitoring and archival data retrieval. TheDisplay Computer further provides a user interface to enable localconfiguration, data display, etc.

FIG. 6 further shows an overview of one embodiment of a flow calculationalgorithm. The uncorrected data from the instruments is gathered via theinternal Modbus interface. Here, ‘uncorrected’ refers to the effects ofmulti-phase flow: the mass flow, density and water cut readings arecalculated based on their single-phase calibration characteristics. Theliquid and gas densities are calculated based on the temperature,pressure and water cut readings and configuration parameters, based ondata provided by the user. Corrections are applied to the Coriolis metermass flow and density readings based on the three-phase flow measurementmodels. Finally, the oil, water and gas measurements are calculated fromthe corrected mass flow, density and water cut.

The corrections to the mass flow and density readings are implementedusing neural networks, based on internally observed parameters. Oneimportant parameter is the density drop, i.e. the difference between thepure liquid density (for a particular water cut value) and the observeddensity of the gas/liquid mixture. For example, FIG. 7 shows a 3-Dvisualization of the observed density drop error against the observedmass flow and density drop, keeping other parameter values constant(e.g. the water cut is 45%). Here zero density drop indicates no gaspresent and, as would be expected, results in no density error. Modelsbased on laboratory experimental data are used to provide on-linecorrections for the mass flow and density readings.

Such models can be used to achieve compliance with oil industrystandards over a wider range of flow conditions. For example, theRussian Standard GOST 8.165 [2] has the following key specifications:

-   -   Total liquid flow accuracy requirement ±2.5%    -   Total gas flow accuracy requirement ±5.0%    -   Total oil flow accuracy requirement dependent upon water cut:        -   For water cuts <70%, oil accuracy requirement ±6.0%        -   For water cuts >70% and <95%, oil accuracy requirement            ±15.0%        -   For water cuts >95%, no oil accuracy requirement is            specified, but an indication of performance may be given

Trials have taken place on the skid 600 at the UK national flowlaboratory, NEL, in Glasgow, and at the Russian national flowlaboratory, VNIIR in Kazan. The resulting performance matches the GOSTrequirements, and the skid 600 has been certified for use in Russia. Forexample, FIG. 8 shows the liquid mass flow errors from 75 formal trialsat NEL, over the full range of water cuts, where the specified accuracyrequirement is ±2.5%. Typically, formal trials at laboratories arecarried out at steady state conditions. For example, in FIG. 8, eachtest result is based on a five minute trial where all referenceconditions are kept constant. The advantage of testing at steady stateis that it reduces the uncertainty of the reference flow rates so thatthe performance of the skid 600 can be accurately assessed at specificoperating points.

In practice, a desired accuracy (uncertainty) performance can only beachieved over a limited range of conditions. For example the maximumtotal liquid flowrate achievable through the skid 600 is likely to bedetermined by pressure drop considerations; conversely the minimum totalliquid flowrate is likely to be constrained by the accuracy performanceof the skid 600 at low flow. With three-phase flow, there are manydimensions to consider in specifying the operating envelope foracceptable measurement uncertainty. For example, as the water cutincreases towards 100%, it becomes increasingly difficult to measure theabsolute oil flow rate to within ±6.0%; in this case the GOST standardvaries the oil flow rate accuracy requirement with the water cut, asdiscussed above. But no such provision is made for the gas flowmeasurement, which is required to be accurate to within 5% in all cases.As the gas volume fraction (GVF) tends to zero, it becomes increasinglydifficult to meet this requirement.

For example, consider a mixture of pure water and gas, where the waterdensity is taken as 1000 kg/m3, the gas density at line temperature andpressure is 5 kg/m3, and the GVF is 5%. Then in every cubic meter ofgas/liquid mixture, there are 950 kg of water, and only 250 g of gas;the GOST standard requires the latter is to be measured to within ±12.5g. To achieve this resolution for gas dispersed within 950 kg of wateris extremely challenging, although this performance was successfullyachieved by the skid 600 in trials at NEL.

Testing performance with static flow conditions in laboratories can thusbe used to set limits on the range of parameters over which the skid 600can deliver the required accuracy performance. In practice, the accuracyof each of the oil, water and gas flow measurements may vary dynamicallywith the operating point (e.g. water cut, GVF and liquid mass flow rate)as well as other conditions (e.g. process noise).

Furthermore, real oil and gas wells often exhibit dynamic behavior. Forexample, FIG. 9 shows data from a field trial of the skid 600 over thecourse of a three hour test. The upper graph shows the proportion byvolume of free gas, oil and water in the produced fluid, while the lowergraph shows the absolute volumetric flow rates. Here the well flow rateand composition shows significant dynamic variation in water cut, GVF,and liquid flow rate.

One major advantage of the skid 600 over conventional separatortechnology is that it provides dynamic measurements, as opposed tosimple totalized flows over a period several hours. Data on the dynamicsof flow are potentially useful to reservoir engineers for understandingthe evolving state of the oilfield.

Conventionally, it is assumed that as long as the operating conditionsfall within the specification of the certification (e.g., GOST)throughout the entire well test period, then the measurement accuracycan be considered to be within the specified limits (e.g., 5% for gasflow). A more pragmatic and flexible approach is to assert that, for aparticular well test, as long as the operating conditions averaged overthe duration of the test fall within the specification of thecertification standard, then nominal accuracy can be assumed.

An alternative approach is to provide a dynamic uncertainty analysis foreach measurement value, as a function of the operating conditions,process noise and other influencing factors. With this approach, theoverall uncertainty of each measurement is estimated, based upon itsdynamic behavior over the course of the well test period. In particular,this approach can facilitate the demonstration of acceptable levels ofuncertainty over wider ranges of operating conditions than for a purelystatic analysis. For example, if the liquid flowrate drops below thethreshold for acceptable accuracy based on a static analysis, a dynamicuncertainty analysis can demonstrate that the contribution of this lowflow to the overall uncertainty of entire test period may be small, andthat the overall well test total flow remains within specification. Thusdeveloping a dynamic uncertainty analysis for the skid 600 can result inacceptable uncertainty performance over a wider range of operatingconditions than is possible using static, laboratory-based verification.

The Sensor Validation (SEVA) concept proposes a model of how a‘self-validating’ or SEVA sensor should behave, assuming theavailability of internal computing power for self-diagnostics, and ofdigital communications to convey measurement and diagnostic data. Thismodel has been incorporated into the British Standard BS-7986 [6]. Ageneric set of metrics are proposed for describing measurement quality.For each measurement, three parameters are generated:

-   -   The Validated Measurement Value (VMV). This is the conventional        measurement value, but if a fault occurs, the VMV is a corrected        best estimate of the true value of the measurand;    -   The Validated Uncertainty (VU). This is the metrological        uncertainty, or probably error, of the VMV. For example, if the        VMV is 4.31 kg/s, and the VU is 0.05 kg/s, then the sensor is        claiming that the true measurement value lies between 4.26 kg/s        and 4.36 g/hour with the stated level of coverage (typically        k=2, 95% probability); and    -   The Measurement Value Status (MV Status). Given the requirement        to provide a measurement, even when a fault has occurred, the MV        Status indicates the generic fault state under which the current        measurement value has been calculated.

One important aspect of the SEVA scheme is the generation of theValidated Uncertainty, a dynamic assessment of the uncertaintyassociated with each measurement value provided by the sensor. In thecase of a complex instrument such as a Coriolis meter, the uncertaintyof each measurement (e.g. the mass flow and density) is calculatedseparately within the instrument, and will vary dynamically withoperating point, process noise and other parameters. On-line uncertaintycan be used for a variety of purposes, such as deciding on controlsystem behavior (e.g. whether to accept or reject the quality of themeasurement value for the purposes of taking control decisions). Wheremeasurements are combined (for example in forming mass balances or otherhigher level calculations), the SEVA scheme proposes the provision of ahigher-level uncertainty analysis, where the dynamic uncertainty of theinput measurements are used in the calculation of the uncertainty of theresulting measurement. Consistency checking between redundant SEVAmeasurements has also been developed.

Dynamic assessments of the uncertainty of each measurement from theCoriolis meter, water cut meter and other sensors can be used togenerate a corresponding on-line uncertainty assessment of thethree-phase measurements of gas, water and oil flow, as indicated inFIG. 11.

In the Guide to the Expression of Uncertainty in Measurement or GUM, anumber of techniques are described for calculating the uncertainty of anoutput variable from the values and uncertainties of input variables. Inthe case of a simple analytical relationship between inputs and output,formulaic expressions can be used. In more complex cases, where forexample there may be correlation between input variables and/or thefunctional relationship is not readily expressed algebraically, MonteCarlo Modeling (MCM) can suitably be used. Monte Carlo Modeling isdescribed in more detail JCGM. “JCGM 101:2008. Evaluation of measurementdata—Supplement 1 to the “Guide to the expression of uncertainty inmeasurement”—Propagation of distributions using a Monte Carlo method”,www.bipm.org, 2008, the contents of which are incorporated by reference.Given the complexity of the three-phase flow calculations, whichincludes neural net models, MCM is a suitable means of assessing outputuncertainty for the skid 600. FIG. 11 illustrates this process, in whichuncertainty from the mass flow and density measurements from theCoriolis meter 215 and uncertainty from the water cut measurement fromthe liquid fraction probe 230 are fed into a Monte Carlo algorithm alongwith the corresponding measurements to yield uncertainty for the flowrates of oil, gas, and water.

To briefly summarize the Monte Carlo method the measurement calculationis carried out multiple times, where in each case the input variables(e.g., mass flow rate, density, and water cut) are randomly selectedbased on their respective probability distributions. With a sufficientnumber of repeat calculations, it is possible to estimate theprobability distribution of each output variable, and thereby tocalculate a mean and coverage interval or uncertainty.

The GUM is primarily intended for static, off-line analyses. In section7 of the GUM, where the number of Monte Carlo trials M is discussed, itis suggested that one million simulations might be appropriate to ensurea good approximation of the distribution of the output variable Y. Thisis clearly unlikely to be feasible in an on-line skid with a is updaterate. Accordingly, one embodiment of a method of providing dynamicuncertainty analysis for the skid 600 includes:

-   -   At the start of each new calculation period, mass flow, density,        water cut, pressure, and temperature measurements are collected        from the skid 600 instrumentation;    -   Estimates of the uncertainties of each of these measurements are        obtained either from the instruments themselves, or in the        interface module 609 of the skid 600;    -   Simple Gaussian distributions are assumed for the probability        density functions. The only likely correlations are between the        mass flow and density measurements—all others can be assumed to        be independent;    -   Monte-Carlo modeling simulation is done by performing between        about 50 and about 100 three-phase measurement calculations        where the input parameters for each calculation are randomly        selected from their assumed Gaussian distributions;    -   The resulting oil, water, and gas mass flow rates are assumed        Gaussian, so that the best estimate and uncertainty of each flow        rate can be calculated from the results of the Monte Carlo        modeling simulation; and    -   The totalized flow and its uncertainty are updated for each        fluid type.

Even with only 50-100 MCM calculations per measurement update, thisapproach requires a substantial increase in the computing powerresources for the skid 600 if it is to be implemented in real-time.However, the benefit is that the dynamic uncertainty analysis may enableassurances to be given that the overall measurement output of the skid600 and the net oil and gas measurement systems based on the skid, suchas systems 110 and 112 on FIG. 2 is within prescribed tolerances forerror under one or more specific standards when such assurances couldnot be made without the dynamic uncertainty analysis.

Referring again to FIG. 2, in a first exemplary method of testing awell, the selection of wells between the first and second net oil andgas measurement systems 110, 112 is generally balanced so that themeasurement systems receive approximately the same combined flowrate.One method of balancing the flow rate from the wells 101 includes theuse of approximate, long-term production rates which are usually knownfor established wells. Using this information, the wells are listed inorder of flow production from highest to lowest, assigning each an indexnumber beginning with 1 for the highest flow rate, 2 for the next, andso on. Thus, as a non-limiting example, Table 1 (below) shows a clusterincluding 10 wells 101. Each of the 10 wells 101 includes a liquid flowrate (kg/s) determined from historical, long-terms production rates. Theuncertainty (abbreviated “unc”) is determined or estimated based on theaccuracy of the measurement systems 110, 112.

TABLE 1 Liquid Flows Rates of each Well Well No. Flow Rate (kg/s) 1 1.002 0.85 3 0.70 4 0.65 5 0.50 6 0.50 7 0.40 8 0.30 9 0.20 10 0.10 TotalFlow Rate 5.20 (kg/s) Uncertainty %   1.00%

After ranking the wells 101 from highest flow rate to lowest flow rate,the wells are grouped based on the first and second net oil and gasmeasurement systems 110, 112. For example, using the ranking set forthin Table 1, the wells are grouped as set forth in Tables 2 and 3(below), where Table 2 relates to the first net oil and gas measurementsystem 110 and Table 3 relates to the second net oil and gas measurementsystem 112, and where a number 1 in the On/Off column means the well isin fluid communication with that measurement system via the respectivevalve 104, and a number 0 means the well is not in fluid communicationwith the measurement system. This ranking may be performed usingsoftware executed on a processor (e.g., controller 130, discussed below)or may be inputted manually by a user. In general the ranking andassigning of the wells to the measurement systems 110, 112 is done in amanner that results in some of the higher producing wells being assignedto each system 110, 112 and some of the lower producing wells beingassigned to each system.

TABLE 2 (First Net Oil and Gas Measurement System) Flow RateContribution Well No (kg/s) On/Off (kg/s) 1 1.00 1 1.00 2 0.85 0 0.00 30.70 1 0.70 4 0.65 0 0.00 5 0.50 1 0.50 6 0.50 0 0.00 7 0.40 1 0.40 80.30 0 0.00 9 0.20 1 0.20 10 0.10 0 0.00 Total Flow Rate 2.80 kg/s TotalUncertainty %   1.00% Total Uncertainty 0.028 kg/s 

TABLE 3 (Second Net Oil and Gas Measurement System) Flow RateContribution Well No (kg/s) On/Off (kg/s) 1 1.00 0 0.00 2 0.85 1 0.85 30.70 0 0.00 4 0.65 1 0.65 5 0.50 0 0.00 6 0.50 1 0.50 7 0.40 0 0.00 80.30 1 0.30 9 0.20 0 0.00 10 0.10 1 0.10 Total Flow Rate 2.40 kg/s TotalUncertainty %   1.00% Total Uncertainty 0.024 kg/s 

In one embodiment, the default or initial configuration of the system100 may be controlled by a controller 130 (i.e., a device including aprocessor and a memory). It is understood that the term “controller” isnot limited to a single device, but may include a plurality of controlcircuits or other hardware, which may or may not be packaged as a singleunit, and may or may not being communication with one another. Forexample, each of the first and second measurement systems 110, 112 mayinclude individual control circuits, and another control circuit may bein communication with the valves 104; however, together each of thesecontrol circuits or controllers constitutes the controller 130 (FIG. 2).The controller 130 may include software that is executed on theprocessor for using data to determine the rankings of the wells and forgrouping the wells. Based on the determined groupings, the controller130 communicates with valves 104 to configure the valves in accordancewith the groupings. The connections between the controller 130 andvarious other components in FIG. 2 are illustrated with dashed lines.These connections may involve physical connections with electrical wiresor may involve wireless communication components.

After determining and instituting the default configuration of the testsystem 100, the controller 130 determines the flow rate of eachindividual well by switching its flow from the default measurementsystem (e.g., measurement system 110) to the other measurement system(e.g., measurement system 112). In one example, to determine the flowrate of well 1 in Tables 1-3, the following steps are carried out by thecontroller 130 in one embodiment of the method:

-   -   (i) the current flow rates from the first and second measurement        systems 110, 112 are recorded with all the wells in their        default groups, averaged over a suitable duration (anything from        5 minutes to 24 hours depending upon application requirements);        these flow rates can be taken for each of oil, water and gas;        the flow rates are denoted below as 1 A and 2 A, with the        understanding that each of oil, water, and gas are separately        measured and calculated along with corresponding uncertainty        estimates if desired;    -   (ii) the valves 104 are used to change the path of well 1 so        that is now sent to the second measurement system instead of the        first measurement system;    -   (iii) wait for a suitable settling time to allow the new flow        pattern to become established (as discussed below);    -   (iv) the flow rates and uncertainty estimates from the first and        second measurement systems 110, 112 in the new configuration are        recorded and averaged over a suitable duration—denoted as 1 B        and 2 B for the measurement systems 110, 112, respectively;    -   (v) the total flows ((1 A+2 A) and (1 B+2 B)) for each of the        two periods are compared to see whether the total flow was        stable, and therefore whether a good estimate of the Well 1 flow        can be made (e.g., if (1 A+2 A) is sufficiently close to (1        B+2 B) then a good estimate of Well 1 flow can be made);    -   (vi) estimates of the flow of Well 1, using (1 A−1 B)=1^(st)        estimate of flow, and (2 B−2 A)=2^(nd) estimate of flow are        calculated; and    -   (vii) the mean/average of the 1^(st) and 2nd estimates is        calculated, using {(1 A−1 B)+(2 B−2 A)}/2.

Tables 4 and 5 (below) show the flow rates using the corresponding valve104 to switch well 1 from the first measurement system 110 to the secondmeasurement system 112.

TABLE 4 Flow Rate Contribution Well No (kg/s) On/Off (kg/s) 1 1.00 00.00 2 0.85 0 0.00 3 0.70 1 0.70 4 0.65 0 0.00 5 0.50 1 0.50 6 0.50 00.00 7 0.40 1 0.40 8 0.30 0 0.00 9 0.20 1 0.20 10 0.10 0 0.00 Total FlowRate 1.80 kg/s Total Uncertainty %   1.00% Total Uncertainty 0.018 kg/s 

TABLE 5 Flow Rate Contribution Well No (kg/s) On/Off (kg/s) 1 1.00 11.00 2 0.85 1 0.85 3 0.70 0 0.00 4 0.65 1 0.65 5 0.50 0 0.00 6 0.50 10.50 7 0.40 0 0.00 8 0.30 1 0.30 9 0.20 0 0.00 10 0.10 1 0.10 Total FlowRate 3.40 kg/s Total Uncertainty %   1.00% Total Uncertainty 0.034 kg/s 

Table 6 (below) shows the totals for 1 A, 1 B, 2 A, and 2 B, as setforth above. Table 7 (below) shows the calculations (1 A−1 B) and (2 B−2A), and Table 8 shows the calculations {(1 A−1 B)+(2 B−2 A)}/2,including an uncertainty percentage.

TABLE 6 Step 1 Step 2 Total (kg/s) Unc (kg/s) Total (kg/s) Unc (kg/s)First 1A = 2.80 0.028 1B = 1.80 0.018 Measurement System (110) Second 2A= 2.40 0.024 2B = 3.40 0.034 Measurement System (112)

TABLE 7 Differences Total (kg/s) Unc (kg/s) (1A − 1B) 1.00 0.033 (2B −2A) 1.00 0.042

TABLE 8 Total (kg/s) Unc (kg/s) Unc (%) Well Flow Estimate 1.00 0.0272.66

In one example, after calculating the estimate of well 1 flow, thedefault path of well 1 can be restored. If desired, another well flowestimate for well 1 can be computed in the same way comparing change inflow rates as well 1 is re-routed from its non-default flow path back toits default flow path. For example, the first and second well flowestimates can be averaged to provide a well flow estimate based on moredata. After waiting a sufficient time for the default flow toreestablish, flow estimates for the other wells can be sequentiallydetermined in the same manner as set forth above for well 1.

The basic flow rate (e.g., total mass flow from each well) can becomputed in the manner set forth above using a wide range of well testsystems. However, it is understood that more sophisticated well testsystems, such as the well test systems 110, 112 which each include a netoil skid 600 performing Monte Carlo simulated uncertainty analysis canprovide well test estimates for each well that includes a more detailedbreakout of flow rate and uncertainty for each constituent (e.g., gas,oil, and water) of the multiphase flow from each well 101.

In another example, systematic tests of all the wells 101 could also becarried out by allowing more complex moves away from the defaultconfiguration. Thus, as with the example set forth above, the wells 101can be ranked in order of flow rate, and all odd numbered wells can begrouped into one group which is associated with the first measurementsystem 110 and all even numbered wells can be grouped in another groupassociated with the second measurement system 112. The following stepsmay be executed by the controller:

-   -   Well 1 is fluidicly re-routed using its respective valve 104        from the first measurement system 110 to the second measurement        system 112, and the flow rate is estimated and recorded for Well        1 in the manner described above;    -   Well 2 is fluidicly re-routed using its respective valve 104        from the second measurement system 112 to the first measurement        system 110, and the flow rate is estimated and recorded for Well        2 in the manner described above;    -   Well 3 is fluidicly re-routed using its respective valve 104        from the first measurement system 110 to the second measurement        system 112, and the flow rate is estimated and recorded for Well        3 in the manner described above;    -   the valves 104 are used to continue re-routing wells 4 through N        one at a time, alternating between (i) re-routing a well from        the first measurement system 110 to the second measurement        system 112 and (ii) re-routing a well from the second        measurement system 112 to the first measurement system 110, with        the flow rate for each of wells 4 through N being estimated and        recorded in the manner described above after that particular        well was re-routed.

Continuing in this way, all N wells can be measured using only N+1recording periods, where each well is estimated from the difference inflows between consecutive averages. At the end of this process, the oddnumbered group originally in fluid communication with the firstmeasurement system 110 is in fluid communication with the secondmeasurement system 112, and vice versa for the even numbered group. Eachflow step can be taken to minimize the change in flow rate observed byeach measurement system 110, 112 (i.e., no more than one well movingfrom one side to the other, and always restoring the balance at the nextmove with the next largest well moving in the other direction),therefore ensuring the least process disruption by the process ofmeasuring wells on an individual basis. Thus in this scenario, there areeffectively two ‘default positions’, with say the first group of wellsall in fluid communication with the first measurement system 110, or allin fluid communication with the second measurement system 112, and thesecond group all on the other measurement system. An efficient means oftesting all the wells entails moving from one default position to theother in a succession of steps with a settling period between steps.

Testing can take place on a scheduled basis, or might occur in responseto an observed change in the behavior of the whole set of wells 101. Forexample, if a change in one or more flow parameters (oil, gas, or waterflows, for example, water cut, gas/oil ratio) is observed among thewhole set of wells 101, then a set of well tests could be commenced toidentify which well(s) are responsible for the change. With theCoriolis-based net oil metering skid 600 able to give accurate readingswithin 5 minutes, it might be possible to identify within an hour or twowhich well 101 or wells is responsible for any significant change in theproductivity of the entire set of wells.

As set forth above, the system 100 may include pressure regulationvalves 116, 118. These valves 116, 118 can be used to ensure consistentinlet pressure even as changes in the configuration of wells takesplace, to ensure the best possible basis for comparing flow rates. Forexample, the well test procedure, could be modified accordingly asfollows:

-   -   (i) record the current flow rates using the first and second        measurement system 110, 112, averaged over a suitable duration;        record the average pressure at the inlets of the first and        second measurement systems;    -   (ii) using the valves 104, change the path of Well 1 so that is        now sent to the second measurement system 112 instead of the        first measurement system 110;    -   (iii) adjust the inlet pressure regulation at the inlets to the        first measurement system 110 and the second measurement system        112 to maintain pressure at the previously recorded levels,        despite the adjustment in respective flowrates; allow a suitable        settling time for the new flow pattern to become established;    -   (iv) record the flow rates using the first and second        measurement system 110, 112 in the new configuration, averaged        over a suitable duration; and    -   (v) repeat for the other wells 101.

Regulating the pressure at the inlet to the measurement systems 110, 112using valve 116, 118 further minimizes the disruption caused to thewells by testing them, and thus helps to maintain consistent flow fromthe wells at all times.

Having described the invention in detail, it will be apparent thatvariations are possible without departing from the scope of theinvention defined in the appended claims.

For instance, the system 100 described above could be modified toinclude additional measurement systems adapted to work in parallel withthe first and second measurement systems 110, 112. Each time anindividual well is to be tested, flow from that individual well isre-routed from one of the multiple measurement systems to a differentone of the multiple measurement systems. One or more of the differencesin total flow at the two measurement systems involved in the switch canbe used in the same manner described above to assess flow from the wellunder test. Each of the multiple measurement systems can be configuredto provide uncertainty estimates, as described above. If one or more ofthe uncertainty estimates fails to meet pre-defined criteria duringtesting of a particular well, the test of that well may be rejected asbeing unreliable and the test may be repeated later in an effort toobtain a more reliable test.

Embodiments of the invention may be implemented with computer-executableinstructions. Computer-executable instructions may be organized into oneor more computer-executable components or modules. Aspects of theinvention may be implemented with any number and organization of suchcomponents or modules. For example, aspects of the invention are notlimited to any specific computer-executable instructions or the specificcomponents or modules illustrated or suggested in the figures anddescribed herein. Other embodiments of the invention may includedifferent computer-executable instructions or components having more orless functionality than illustrated and described herein.

For purposes of illustration, processors, programs and other executableprogram components, such as the controller 130, the interface module609, and other components are sometimes illustrated herein as discreteblocks. It is recognized, however, that such programs and componentsrelated to the systems described herein may reside in different storagecomponents and may be executed by data processor(s) of differentdevices, and different combinations of devices, than those illustrated.

The order of execution or performance of the operations in embodimentsof the invention illustrated and described herein is not essential,unless otherwise specified. That is, the operations may be performed inany order, unless otherwise specified, and embodiments of the inventionmay include additional or fewer operations than those disclosed herein.For example, it is contemplated that executing or performing aparticular operation before, contemporaneously with, or after anotheroperation is within the scope of aspects of the invention.

When introducing elements of the present invention or the preferredembodiments(s) thereof, the articles “a”, “an”, “the” and “said” areintended to mean that there are one or more of the elements. The terms“comprising”, “including” and “having” are intended to be inclusive andmean that there may be additional elements other than the listedelements.

In view of the above, it will be seen that the several objects of theinvention are achieved and other advantageous results attained.

As various changes could be made in the above constructions, products,and methods without departing from the scope of the invention, it isintended that all matter contained in the above description and shown inthe accompanying drawings shall be interpreted as illustrative and notin a limiting sense.

What is claimed is:
 1. A method of assessing flow from an individualwell in a set of oil and gas wells, the method comprising: flowingoutput from a first subset of the wells collectively to a first flowmeasurement system through a first conduit while flowing output from asecond subset of the wells collectively to a second flow measurementsystem through a second conduit different from the first conduit;measuring total flow through the first flow measurement system and totalflow through the second flow measurement system; re-routing output fromsaid individual well from one of said first and second flow measurementsystems to the other of said first and second flow measurement systems;measuring total flow through at least one of the first and second flowmeasurement systems after the re-routing and using a difference of thetotal flow before the re-routing and after the re-routing to assess flowfrom said individual well.
 2. The method as set forth in claim 1 whereinassessing flow comprises assessing a mass flow rate of at least one ofgas, oil, water, and any combinations thereof.
 3. The method as setforth in claim 1 wherein assessing flow comprises assessing a volumetricflow rate of at least one of gas, oil, water, and any combinationsthereof.
 4. The method as set forth in claim 1 wherein assessing flowfrom said individual well comprises assessing net oil flow from saidindividual well.
 5. The method as set forth in claim 1 wherein all wellsin said set of wells are included in one of the first and second subsetsof wells.
 6. The method as set forth in claim 1 further comprising:flowing output from a third subset of the wells collectively to a thirdflow measurement system through a third conduit; measuring total flowthrough the third flow measurement system; re-routing output from anindividual wells in said third subset from the third flow measurementsystem to one of said first and second flow measurement systems;measuring total flow through the third flow measurement system after there-routing and using a difference of the total flow before there-routing and after the re-routing to assess flow from said individualwell in said third subset.
 7. The method as set forth in claim 1 furthercomprising: re-routing output from another of said individual wells fromone of said first and second flow measurement systems to the other ofsaid first and second flow measurement systems; measuring total flowthrough at least one of the first and second flow measurement systemsafter the re-routing; and using a difference of the total flow beforethe re-routing and after the re-routing to assess flow from said anotherindividual well.
 8. The method as set forth in claim 1 wherein measuringtotal flow through the first flow measurement system and total flowthrough the second flow measurement system comprises measuring the totalflow for each of the first and second flow measurement systems using aCoriolis flowmeter and a water cut meter.
 9. The method as set forth inclaim 1 wherein measuring total flow through the first flow measurementsystem and total flow through the second flow measurement systemcomprises measuring a multiphase flow without separating the flow intodifferent fluid factions before measuring the multiphase flow.
 10. Themethod as set forth in claim 1 further comprising using a pressureregulating valve for each of the first and second flow measurementsystems to maintain constant pressure at inlets of the first and secondflow measurement systems notwithstanding changes in the flow through thefirst and second flow measurement systems resulting from the re-routing.11. The method as set forth in claim 1 wherein the flow through each ofthe first and second flow measurement systems comprises a multiphaseflow including oil, water, and gas, the method further comprisingdetermining dynamic estimates of uncertainty of each of an oil mass flowrate, a water mass flow rate, and a gas mass flow rate for the first andsecond flow measurement systems.
 12. The method as set forth in claim 11wherein determining dynamic estimates of the uncertainty of each of theoil mass flow rate, the water mass flow rate, and the gas mass flow ratefor the first and second flow measurement systems comprises using MonteCarlo modeling.
 13. The method set forth in claim 1 further comprisingcalculating a difference resulting from the re-routing in the total flowto each of said first and second flow measurement systems.
 14. Themethod as set forth in claim 13 further comprising calculating anaverage of the differences resulting from the re-routing in total flowfor the first and second flow measurement systems.
 15. The method as setforth in claim 14 further comprising calculating an output of aparameter associated with the selected well as a function of saidaverage.